- Liquids Production Grows to 3,900 Barrels per Day (62% Oil, 38% Natural Gas Liquids ("NGLs")), with Approximately Two-Thirds of Revenue Generated from Liquids. Oil Revenues Grow to Over 50% of Total Revenue, while NGL Production and Processing Provides 23% Uplift to Realized Natural Gas Price

- Adjusted EBITDAX Grows by 20% Over Prior Year Period to $40.4 Million

- Tuscaloosa Marine Shale Acreage Grows to 102,600 Net Acres with Initial Well in Completion Phase and Flowback to Commence within One to Two Weeks

- Capital Expenditure Budget Reaffirmed at $250 - 275 Million with $25 Million Earmarked for Potential Incremental Drilling in the Tuscaloosa Marine Shale Based on Ongoing Positive Results

- Borrowing Base Affirmed at $265 Million, Providing $131.5 Million of Proforma Liquidity at the End of the Quarter

CASH FLOW
Adjusted earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration ("EBITDAX") increased by 20% to $40.4 million in the quarter, compared to $33.7 million in the prior year period (see accompanying table for a reconciliation of EBITDAX, a non-GAAP financial measure, to net loss). Adjusted EBITDAX was 5% lower sequentially due to lower natural gas prices.

Discretionary cash flow ("DCF") increased by 12% to $29.9 million in the quarter, compared to $26.8 million in the prior year period. Net cash provided by operating activities for the year increased by 369% to $30.5 million, compared to $6.5 million for the prior year period (see accompanying table for a reconciliation of discretionary cash flow, a non-GAAP financial measure, to net cash provided by operating activities).

NET INCOME
The Company announced a net loss applicable to common stock of $19.2 million for the quarter, or ($0.53) per basic share, versus a net loss applicable to common stock of $24.7 million, or ($0.68) per basic share in the prior year period.

PRODUCTION
Production for the quarter was 8.8 billion cubic feet equivalent ("Bcfe"), or an average of approximately 96,000 Mcfe per day, versus 9.1 Bcfe, or an average of 100,800 Mcfe per day in the prior year period. Oil production for the quarter grew by 167% versus the prior year period to 217,000 barrels of oil, or an average of approximately 2,400 barrels per day, versus 80,000 barrels of oil, or approximately 900 barrels per day in the prior year period. Natural gas production for the quarter totaled 7.5 Bcf, or an average of approximately 82,000 Mcf per day.

We have taken steps to achieve significant improvements in realizing liquids value from our natural gas production. In the liquids rich Cotton Valley play in East Texas, the Company entered into a new gas gathering, transportation and processing contract which allowed the Company to process effectively 100% of our natural gas production in the Beckville, Minden and South Henderson fields. Approximately 95% of our natural gas which is processed is located in these fields in East Texas. On a Company-wide basis, during the quarter, we processed approximately 40% of our natural gas production which resulted in production of approximately 1,500 barrels per day of natural gas liquids ("NGLs"), which are included in our reported natural gas production.

As a result of the additional processing, our net natural gas price realization increased over our net blended East Texas field pricing (NGPL-TxOk) by approximately $0.50 per Mcfe to $2.99 per Mcfe and by approximately $0.55 per Mcfe over first quarter average Henry Hub pricing of $2.44 per Mcfe. Also, impacted by the new contract, transportation and processing expense of $0.47 per Mcfe for the quarter was $0.10 per Mcfe above the midpoint of previously issued guidance.

Natural gas production in the quarter was reduced by curtailment due to low natural gas prices and a workover of a well in the Company's Angelina River Trend. Oil production was relatively flat sequentially due to the nature of multiple well pad drilling in the Eagle Ford Shale Trend, which caused the Company to defer completions on a number of wells and temporarily shut-in offset wells while engaging in fracking operations. The Company completed and added to production 3 gross (2 net) Eagle Ford Shale wells during the quarter, with 2 gross (1.5 net) additional wells producing for the entire quarter.

The Company has elected to defer completion on all operated gas wells, and all but two minority interest gas wells operated by others, for the remainder of 2012. The Company now expects natural gas production for the year to be 5 – 10% lower than previous guidance.

Production for the second quarter of 2012 is expected to average between 91,000 – 96,000 Mcfe per day. Oil production is expected to average between 3,000 – 3,200 barrels per day. Oil production guidance for the second quarter reflects the anticipated ongoing impacts of pad drilling in the Eagle Ford Shale, including the timing of completions and shut-ins of offset producing wells during fracking operations. We expect oil production to grow to 20 – 25% of total production in the second quarter, up from 15% in the first quarter. Natural gas production is expected to average between 73,000 – 77,000 Mcfe per day, which includes natural gas liquids.

REVENUES
Revenues for the quarter were $45.3 million versus $41.2 million in the prior year period. Revenues, including realized gain on derivatives not designated as hedges of $15.9 million for the quarter, would have been $61.2 million. Average realized price per unit for the quarter, prior to factoring in the Company's hedges, was $5.18 per Mcfe, versus $4.51 per Mcfe in the prior year period. When factoring in the Company's hedges, average realized price per unit was $6.99 per Mcfe, versus $5.30 per Mcfe in the prior year period.

As a result of the new processing agreement in East Texas mentioned above, the Company's transportation and processing expense increased to $0.61 per Mcfe in the quarter in those fields, which increased our Company-wide transportation and processing expense to $0.47 per Mcfe, while natural gas revenue received an uplift by approximately $1.79 per Mcfe in these fields. As a result, our Company-wide net natural gas price realization received an incremental benefit of $0.55 per Mcfe over first quarter average Henry Hub pricing of $2.44 per Mcfe to $2.99 per Mcfe.

CRUDE OIL AND NATURAL GAS DERIVATIVES
The Company incurred a realized gain of $15.9 million on its derivatives not designated as hedges and an unrealized loss of $6.5 million for a net gain of $9.4 million for the quarter.

For the remainder of 2012, the Company has 60,000 MMBtu per day of natural gas hedged, or approximately 80 – 83% of updated guidance, at an average floor price of $5.78 per MMBtu, and 3,000 barrels of oil per day hedged at an average price of $101.18 per barrel. The Company recently hedged an additional 500 barrels of oil per day with a swap at $104.25 per barrel in 2012 (May through December) and at $103.15 per barrel in 2013.

OPERATING EXPENSES
Lease operating expense ("LOE") was $8.4 million in the quarter, or $0.95 per Mcfe, versus $4.9 million, or $0.54 per Mcfe in the prior year period. LOE included $2.3 million or $0.26 per Mcfe for workovers performed in the first quarter, primarily in the Angelina River Trend where the Company replaced tubing in the Nelson 1H well. The LOE rate excluding workovers was $0.69 per Mcfe, in line with previously issued guidance. For the remainder of 2012, the Company expects LOE to average between $0.75 – 0.85 per Mcfe.

Production and other taxes for the quarter were $2.0 million or $0.23 per Mcfe, versus $1.0 million, or $0.10 per Mcfe in the prior year period, driven by higher oil volumes which carry a higher tax rate.

Transportation and Processing expense was $4.1 million or $0.47 per Mcfe in the quarter, versus $2.4 million, or $0.26 per Mcfe in the prior year period. Transportation and processing expense was impacted by increased processing cost of $0.20 per Mcf under the new East Texas processing agreement, which resulted in per unit transportation and processing expense coming in $0.10 per Mcfe above the mid-point of the previous guidance range. For the remainder of 2012, the Company expects transportation expense to average between $0.35 – 0.50 per Mcfe.

Depreciation, depletion and amortization ("DD&A") expense for the quarter totaled $32.3 million or $3.68 per Mcfe, versus $25.0 million, or $2.75 per Mcfe in the prior year period. DD&A per unit decreased by 5% from the prior quarter.

Exploration expense was $2.2 million or $0.25 per Mcfe for the quarter, versus $2.4 million, or $0.27 per Mcfe in the prior year period. Approximately 58% of exploration expense for the quarter was non-cash associated with amortization of the Company's undeveloped leasehold.

Impairment expense was $2.7 million, or $0.30 per Mcfe for the quarter versus no impairment in the prior year period. Impairment expense during the quarter was due to falling natural gas prices related to certain non-core fields.

General and Administrative ("G&A") expense was $7.9 million, or $0.90 per Mcfe in the quarter, versus $8.3 million, or $0.91 per Mcfe in the prior year period. For the quarter, the Company recorded non-cash general and administrative expenses related to stock based compensation for its officers and employees of $1.6 million, or $0.18 per Mcfe, versus $1.8 million, or $0.20 per Mcfe in the prior year period.

OPERATING INCOME
Operating income, defined as revenues minus operating expenses, totaled a loss of $14.2 million for the quarter, which includes $2.7 million of asset impairments, versus an operating loss of $2.4 million for the prior year period.

INTEREST EXPENSE
Interest expense for the quarter was $12.9 million or $1.47 per Mcfe, versus $10.8 million, or $1.19 per Mcfe in the prior year period. Non-cash interest expense comprised 24% of the total, or $3.1 million ($0.36 per Mcfe).

LIQUIDITY
The Company exited the quarter with $131.5 million of proforma liquidity, with $133.5 million drawn on its senior bank revolving credit facility, under which the Company has a recently affirmed borrowing base of $265 million. The Company expects to finance its 2012 capital expenditure budget with cash flow from operations and borrowings under its senior bank revolving credit facility. This expectation is predicated upon numerous assumptions which include oil and natural gas pricing, drilling activity and production additions.

CAPITAL EXPENDITURES AND UPDATED GUIDANCE Capital expenditures for the quarter were $61.4 million, of which $54.4 million was spent on drilling and completion costs, and $7.0 million on leasehold acquisition, facilities and other expenditures. We spent $37.1 million or 61% of our capital in the Eagle Ford Shale Trend and $3.8 million or 6% in the Tuscaloosa Marine Shale, for a total of $40.9 million or 67% of our capital on oil-directed activity. For the year, we expect to spend 80% of our capital expenditure budget on oil-directed activity. We do not anticipate any additional Company operated gas-directed capital spending for 2012, and we anticipate very limited non-operated gas-directed capital spending for the rest of 2012.

The Company reaffirms its full year 2012 capital expenditure budget of $250 – 275 million, with the incremental $25 million earmarked for potential drilling activity in the Tuscaloosa Marine Shale based on ongoing positive results. Within the $250 million budget, the Company is further reducing gas-directed capital expenditures by approximately $10 million and increasing its leasehold acquisition budget by a similar amount, allocated primarily to the Tuscaloosa Marine Shale.

The further reduction of gas-directed capital is anticipated to reduce 2012 natural gas production volumes from previous guidance by 5 – 10% to an average of approximately 72,000 – 75,000 Mcf per day. Incorporating lower natural gas volumes at an estimated natural gas price of $2.50 per Mcf, when factoring in our natural gas hedges, the Company expects a negative impact to cash flow from previous guidance of approximately $10 million.

OPERATIONAL UPDATE
The Company is currently running three operated rigs in the Eagle Ford Shale Trend. For the quarter, the Company's completions were back-end loaded, with 6 gross (4 net) wells added to production, of which 3 gross (2 net) wells produced for the entire quarter. Currently, the Company does not have any non-operated activity to report and anticipates minimal non-operated activity for the remainder of the year.

Tuscaloosa Marine Shale TrendThe Company has increased its acreage position in the play by approximately 17,800 net acres, for $4.3 million, bringing the total acreage position to approximately 102,600 net acres.

The Company has participated for an approximate 5% non-operated working interest in the Anderson 17H-1 well in Amite County, Mississippi. The well, which was drilled with an approximate 7,300 foot lateral and completed with 30 frac stages, is in the completion phase with flowback expected to begin within one to two weeks. For the remainder of 2012, the Company currently expects to participate in two to four additional non-operated wells and two to five operated wells, with a capital expenditure allocation of $20 – 45 million. The Company's first operated well, the Denkmann 33 H-1, is expected to commence by the end of May.

OTHER INFORMATION
In this press release, the Company refers to several non-GAAP financial measures, Adjusted EBITDAX,discretionary cash flow and Drilling and Completion capital expenditures. Management believes that the first two of these measures are good financial indicators of the Company's ability to internally generate operating funds, while the third is a useful measure of the Company's annual drilling expenditures. Neither discretionary cash flow nor Adjusted EBITDAX should be considered an alternative to net cash provided by operating activities, as defined by GAAP, nor should Drilling and Completion capital expenditures be considered an alternative to Costs incurred in oil and gas property acquisition, exploration, and development activities, as defined by GAAP. Management believes that all of these non-GAAP financial measures provide useful information to investors because they are monitored and used by Company management and widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and gas exploration and production industry.

Period to period information included in this press release is to the comparable quarter of the prior calendar year, except for comparisons designated as sequential, which are to the most recent quarter.

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale gas resource plays and tight gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

Certain statements in this news release regarding future expectations and plans for future activities may be regarded as "forward looking statements" within the meaning of the Securities Litigation Reform Act. They are subject to various risks, such as financial market conditions, changes in commodities prices and costs of drilling and completion, operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company's Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Goodrich Petroleum is an independent oil and gas exploration and production company listed on the New York Stock Exchange. The majority of its properties are in Louisiana and Texas.

GOODRICH PETROLEUM CORPORATION

SELECTED INCOME AND PRODUCTION DATA

(In Thousands, Except Per Share Amounts)

Three Months Ended

March 31,

2012

2011

Volumes

Natural gas (MMcf)

7,466

8,594

Oil liquids (MBbls)

217

80

MMcfe - Total

8,765

9,075

Mcfe per day

96,324

100,833

Total Revenues

$ 45,308

$ 41,231

Operating Expenses

Lease operating expense

8,354

4,903

Production and other taxes

1,993

950

Transportation

4,128

2,386

Depreciation, depletion and amortization

32,278

24,959

Exploration

2,213

2,416

Impairment

2,662

-

General and administrative

7,921

8,250

Gain on sale of assets

-

(236)

Operating loss

$ (14,241)

$ (2,397)

Other income (expense)

Interest expense

$ (12,913)

$ (10,828)

Interest income and other

-

12

Gain (loss) on derivatives not designated as hedges

9,425

(10,010)

Gain from extinguishment of debt

-

55

$ (3,488)

$ (20,771)

Loss before income taxes

$ (17,729)

$ (23,168)

Income tax benefit

-

-

Net loss

(17,729)

(23,168)

Preferred stock dividends

1,512

1,512

Net loss applicable to common stock

$ (19,241)

$ (24,680)

Unrealized loss on derivatives not designated as hedges

$ 6,468

$ 17,158

Gain on sale of assets

-

(236)

Gain on extinguishment of debt

-

(55)

Impairment

$ 2,662

$ -

Adjusted net loss applicable to common stock (1)

$ (10,111)

$ (7,813)

Discretionary cash flow (see non-GAAP reconciliation) (2)

$ 29,946

$ 26,770

Adjusted EBITDAX (see calculation and non-GAAP reconciliation)( 3)

$ 40,357

$ 33,728

Weighted average common shares outstanding - basic

36,338

36,093

Weighted average common shares outstanding - diluted (4)

36,338

36,093

Earnings per share

Net loss applicable to common stock - basic

$ (0.53)

$ (0.68)

Net loss applicable to common stock - diluted

$ (0.53)

$ (0.68)

Adjusted earnings per share

Adjusted net loss applicable to common stock - basic (1)

$ (0.28)

$ (0.22)

Adjusted net loss applicable to common stock - fully diluted (1)

$ (0.28)

$ (0.22)

(1) Adjusted net income applicable to common stock is defined as net income (loss) applicable to common stock adjusted to exclude certain charges or amounts in order to provide users of this financial information with additional meaningful comparisons between current results and the results of prior periods. Management presents this measure because (i) it is consistent with the manner in which the company's performance is measured relative to the performance of its peers, (ii) this measure is more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

(2) Discretionary cash flow is defined as net cash provided by operating activities before changes in operating assets and liabilities. Management believes that the non-GAAP measure of operating cash flow is useful as an indicator of an oil and gas exploration and production company's ability to internally fund exploration and development activities and to service or incur additional debt. The company has also included this information because changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and may not relate to the period in which the operating activities occurred. Operating cash flow should not be considered in isolation or as a substitute for net cash provided by operating activities prepared in accordance with GAAP.

(3) Adjusted EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. Other excluded items include Interest income and other, Gain (loss) on sale of assets, Gain on early extinguishment of debt and Other expense

(4) Fully diluted shares excludes approximately 10.1 million potentially dilutive instruments that were anti-dilutive due to the net loss applicable to common stock for the year to date period ended March 31, 2012. We report our financial results in accordance with accounting principles generally accepted in the United States of America ("GAAP"). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.